The introduction and integration of distributed energy resources (DER) into the electric power system (EPS, or “grid”) has become a priority in the modern energy era. DERs include that of generation (such as photovoltaic, wind, diesel, and natural gas generators), demand (such as buildings, homes, and electric vehicles), and storage (such as batteries, flywheels, capacitors, and pumped hydro) resources. In particular, the integration of renewable energy sources and electric vehicles onto the grid has many important economic and environmental benefits. Distributed energy storage (DES) is considered a “missing piece” of the distribution system, performing functions such as peak shaving/valley filling, volt/var optimization, capacity relief, power quality management, buffering the intermittency and variability of supply (e.g. renewable generation) and demand (e.g. electric vehicle charging), providing backup power, and participating in power system ancillary services.
The EPS was originally designed with one-way power flow from the centralized generators to end loads. As DERs apply for access onto the grid, utilities conduct a breadth of analyses to determine its potential effects on the system. Through a connection impact assessment process, utilities perform studies to evaluate parameters including voltage, frequency, power factor, clearing times for protection, load/generation balance, transfer/remote trip, and reconnection times. With a small amount of distributed generation (DG) connections on a power system feeder relative to its load levels, hence a lower level of penetration, the strength of the main grid will mitigate any issues from the DGs and there will be no concerns for affecting grid operating standards.
One challenge is that as DGs come online at a higher level of penetration, the strength of the connected DGs will affect, at least on an aggregate level in a local area, the operating conditions of the grid and raise tangible technical concerns with the safe, reliable, and cost-effective operation of the EPS. Effects include complex and two-way power flows, intermittent and variable generation, and power quality phenomena. The result is an ever-increasing complexity in planning and operating the grid, and potentially requires infrastructure upgrades, such as in the form of cables, wires, switchgear, transformers, controls, and grid communications, to accommodate the extra capacity from DGs.
Challenges associated with demand resources include that of passive and unresponsive loads, lack of demand elasticity, uncertainty and variability over rising impact of electric vehicle charging demand, lack of direct control, and that current direct control is based on pricing or bulk power system signals, rather than coordinated with local distribution system opportunities and constraints.
Challenges associated with DES include cost of equipment, cost of installation, uncertain business model (including ownership and revenue streams), and uncertain operating schemes for multi-service applications. In particular, current operating schemes for DES are often limited to static, pre-programmed, and time-of-use settings, external command and control, and decision making from locally monitored variables.
Combining multiple DERs, a microgrid can be formed to operate in concert with the main grid in grid-connected mode or autonomously and independently from the grid in islanded mode. Challenges associated with microgrids include cost of equipment, cost of installation, uncertain business model, and uncertain operating schemes for multi-service, multi-tiered applications. A microgrid typically needs to optimize the operation of its internal DERs within the microgrid, as well as offer services to the upstream distribution system for inter-tiered operation. The microgrid may also need to dynamically reconfigure the topology and connection into the distribution system to its grid-connected and islanded operations.
Management and automated operation of DERs are important to enable and facilitate their integration and avoid costly infrastructure upgrades. Without proper and intelligent controls coordinated with the utility, these resources will treat the grid as a “black box” and supply or consume uncontrolled, unmanaged power to and from the grid, and continue to press ever-higher demands and stress on an already aging and congested grid. Many of today's DERs are unmonitored, uncontrolled, and only has local protection that are static and “set-and-forget”, without realizing value from the myriad of coordinated grid services. Utilities currently carry out connection impact assessments (CIA) on DER applications to connect. For DERs that exceed grid conditions upon connection, utilities may deny access to the EPS or request certain upgrades to be done on the grid or at the DER site.
Today's Distribution Management Systems (DMS) are typically not Energy Management Systems (EMS). Their primary purpose is for work scheduling, system switching, and outage management, while integrating with a utility's Geographical Information System (GIS) and Customer Information System (CIS). Distribution systems were furthermore operated as an on/off switching network, where the major system functions are to maintain continuity of service, reroute power, detect faults, and restore customers. In contrast, EMS functions are performed on supply and demand sides. Energy management on the supply side is typically performed on the bulk power system (e.g. by the independent system operators) with centralized generators on the energy market, to perform functions including unit commitment, economic dispatch, optimal power flow, ancillary services, and regulation services while maintaining minute by minute supply/demand balance. Energy management on the demand side is typically performed through conservation and demand response programs and premise (e.g. building, home) management and automation systems. Both of these approaches have little or no significance for distribution system operations. Upstream and downstream management systems are not interoperating with the distribution system's DMS, and little value can be attained for the local distribution companies. The rise of Distributed Energy Resource Management Systems (DERMS) attempts to address the optimal dispatch of DERs, but rarely considers distribution system dynamic constraints and real time operations in its decision making.
The integration of DERs is typically managed as follows:                Restrict access—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection will adversely impact the EPS and are not allowed to connect to the grid. This method does not facilitate the integration of DERs on the EPS.        EPS expansion—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection may adversely impact the EPS and are allowed to connect to the grid, but utility infrastructure expansions such as cables, wires, transformers, and circuit breakers will be required. This method can accommodate a level of penetration of DERs on the EPS in proportion to the level of expansions, but will be expensive and labor intensive.        Protected and unmanaged DER—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection will not adversely impact the EPS and are allowed to connect to the grid without real time management in the form of monitoring and control. Protection systems are in place such as fault detection, isolation, and anti-islanding. This method can only accommodate a low level of penetration of DERs on the EPS.        Monitored and protected DER—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection may adversely impact the EPS, but it is allowed to connect to the grid, with DER operating conditions monitored and sent back to the utility. Protection systems are in place such as fault detection, isolation, and anti-islanding. This method can typically only accommodate a low level of penetration of DERs on the EPS.        Centralized management of DER—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection may adversely impact the EPS but are allowed to connect to the grid with DER management. Management is carried out centrally in the utility network operating centre (NOC) with communications, monitoring, and control to all DER sites, typically in the form of Supervisory Control and Data Acquisition (SCADA) systems, Distribution Management Systems (DMS), Distribution Energy Management Systems (DEMS), or Distributed Energy Resource Management Systems (DERMS). This method can potentially accommodate a high level of penetration of DERs on the EPS, but can be expensive, non-modular, non-scalable, with high operational latencies, and complex integration challenges.        Decentralized management of DER—through connection impact assessments and system planning studies, utilities determine that the proposed DER connection may adversely impact the EPS but are allowed to connect to the grid with DER management. Management is carried out in a decentralized fashion along the EPS, with communications, monitoring, and control to all DER sites, such as in the form of smart inverters, and coordinated centrally with the utility network operating centre (NOC). This method can be less expensive, more modular, scalable, operationally faster, and simpler to integrate as a decentralized management solution, but today's state-of-the-art lacks the power system analysis and control capabilities of centralized solutions, with primary functions restricted to remote monitoring and disconnect/reconnect.        
In addition to DERs, distributed information resources (DIR) have a critical role in the integrated and coordinated operation of the EPS, especially in the development of smart and intelligent grids. DIRs include that of information generation (such as sensors, smart meter, metering collectors, line monitors, and other data systems), consumption (such as human machine interfaces, visualization tools, business intelligence tools, intelligent electronic devices, switch controllers, circuit breakers, capacitor controllers, reclosure controllers, voltage regulator controllers, power electronic settings, operating modes, utility network operating centers, and other control devices and data systems), and storage (such as local databases, central databases, and cloud-based systems) resources.
The EPS was originally designed as an analog system without DIRs, with decisions and control actions being made using local measurements. With the advance of information and communications technology (ICT), the EPS has seen a substantial increase in the number of DIRs. These DIRs can be interconnected via a main backhaul to a centralized computing system such as SCADA and DMS, a distributed backhaul to a centralized computing system, or a distributed backhaul to distributed computing systems.
Challenges with DIRs include that of two-way information flow, data volume, scalability, security, privacy, disparate communication paths to centralized or distributed computing systems, interoperability in communications, and inoperability in functional operations. These become barriers to integrated and coordinated grid operations, such as in crossing multiple functional streams (e.g. smart metering data for billing, asset management, and real time system operations).